Petroleum refiners often produce desirable products such as turbine fuel, diesel fuel, and other products known as middle distillates, as well as lower boiling hydrocarbonaceous liquids such as naphtha and gasoline, by hydrocracking a hydrocarbon feedstock derived from crude oil. Feedstocks most often subjected to hydrocracking are gas oils and heavy gas oils recovered or derived from crude oil by distillation or by thermal or catalytic processes. A typical heavy gas oil includes a substantial portion of hydrocarbon components boiling above about 371° C. (about 700° F.), usually at least about 50% by weight boiling above 371° C. (about 700° F.). A typical vacuum gas oil normally has a boiling point range between about 315° C. (about 600° F.) and about 565° C. (about 1050° F.).
Hydrocracking is generally accomplished by contacting the gas oil or other feedstock with a suitable hydrocracking catalyst under conditions of elevated temperature and pressure in the presence of hydrogen so as to yield a product containing a distribution of hydrocarbon products desired by the refiner. The operating conditions and the hydrocracking catalysts chosen within a hydrocracking reactor influence the yield of the hydrocracked products.
There is thereby produced a reaction zone effluent stream that includes an admixture of the remaining hydrogen which is not consumed in the reaction, light hydrocarbons such as methane, ethane, propane, butane, and pentane formed by the cracking of the feed hydrocarbons, reaction by-products such as hydrogen sulfide and ammonia formed by hydrodesulfurization and hydrodenitrification reactions that occur simultaneously with the hydrocracking reaction. The reaction zone effluent will also contain the desired product hydrocarbons boiling in the naphtha, gasoline, diesel fuel, kerosene, or fuel oil boiling point ranges and some unconverted feed hydrocarbons boiling above the boiling point ranges of the desired products. The effluent of the hydrocracking reaction zone therefore includes an extremely broad and varied mixture of individual compounds.
The hydrocracking reaction zone effluent is typically removed from contact with the catalyst bed, heat exchanged with the feed to the reaction zone, and then passed into a vapor-liquid separation zone normally referred to as a high pressure separator. Additional cooling can be done prior to this separation. In some instances a hot flash separator is used upstream of the high pressure separator. The use of cold separators to remove condensate from vapor removed from a hot separator is another option. The liquids recovered in these vapor-liquid separation zones are passed into a product recovery zone containing one or more fractionation columns Product recovery methods for hydrocracking are well known and conventional methods may be employed.
Gas oils and other feedstocks may also include some level of impurities, such as sulfur and nitrogen. These impurities are often undesirable, and their removal from the hydrocracked product is typically sought. For example, due to environmental concerns and newly enacted rules and regulations, saleable fuels must meet lower and lower limits on contaminates, such as sulfur and nitrogen. New regulations require essentially complete removal of sulfur from diesel. For example, the ultra-low sulfur diesel (ULSD) requirement is typically less than about 10 wppm sulfur.
With regard to the removal of sulfur impurities, sulfur guard beds are often specified to treat hydrocracked naphtha where the sulfur concentration in the naphtha (as mercaptans arising from recombination reactions in the hydrocracking beds) must be guaranteed as suitable for naphtha reforming and/or isomerization processing downstream. These beds are non-regenerable, and the spent material is a very hazardous waste (carcinogenic, pyrophoric) and requires periodic disposal, which adds undesirable costs to the process.
Accordingly, it is desirable to provide improved methods and systems for removing sulfur impurities from hydrocracked hydrocarbon streams. Furthermore, it is desirable to provide such methods and systems that reduce the costs associated with sulfur impurity removal. Still further, it is desirable to provide such methods and system that do not require the use of non-regenerable components and that do not produce hazardous/toxic waste by-products. Embodiments of the present disclosure have the feature that the catalyst employed may be periodically regenerated, in situ or ex situ, at the same time that the system is periodically shut down for regularly scheduled maintenance. Furthermore, other desirable features and characteristics of the presently disclosed embodiments will become apparent from the subsequent detailed description and the appended claims, taken in conjunction with the accompanying drawings and this background.